The shift to the production of ultra clean fuels and chemicals from refineries combined with a focus on minimizing greenhouse gases warrants revisiting the integration of the fluid catalytic cracking unit (FCCU) within a conventional refinery setting. Evolving technologies can allow refiners to restructure their processing and phase into the heteroatom free products demanded by the marketplace. Additive technology, such as RESOLVE®, can be utilized both in the transition process allowing for additional time for directions in the market to become clearer and structurally as part of an integrated solution. Integration of improved desulfurization catalyst technology directly into the design of the FCCU offers the potential to simplify the refinery processing scheme and provide some interesting advantages in many applications.
In Canada, between July 2002 and Jan. 1, 2005, refiners were required to meet an interim average gasoline sulfur specification of 150 wppm (parts per million by weight). Starting Jan. 1, 2005, the specification was lowered to 30 wppm. The phasing in of the gasoline sulfur specifications will be followed by a distillate maximum sulfur specification of 15 wppm on Jun. 1, 2006. This has resulted in a critical examination of the effectiveness of different approaches and future product demands.
From a refiner's perspective, there are a significant number of unknowns in moving forward with capital expenditures. What appears to be an obvious solution today may not be tomorrow. Evolving technologies both to produce and utilize the products significantly may change the demand and product slate from the refineries. The push forward into a hydrogen economy may not happen as quickly as many have anticipated. In North America a shift from gasoline to distillate may not occur. Practical solutions for making the transition to more environmentally friendly products may be achievable with the industry's base infrastructure.
Feedstock quality also will influence the refining infrastructure. For example, evolving technologies allow for low hydrogen and high sulfur content tar sands bitumen to be viable feedstocks. Tar sands provide a long term security of supply. Infrastructure built into the primary upgrading will influence how a refiner adapts by reconfiguring refining complexes to process feedstocks derived from tar sands.
General Criteria for the Evolution Are:
1. Effective utilization of hydrogen and the subsequent balancing of carbon in the products in any configuration                2. Energy efficiency        3. Reduction of CO2 generation        4. Reduction of gaseous and particulate emissions        
The FCCU is a carbon rejection and hydrogen transfer device. The FCC process tailors the carbon distribution based on the hydrocarbon structures in the feedstock and the drive towards equilibrium in the cracking process. Historically, the FCCU has been viewed as a relatively inexpensive gasoline and light olefin generator that now has significant application as a residual oil upgrader. FCCU and their constituent parts are well known in the art, examples of FCCU can be found in U.S. Pat. Nos. 2,737,479; 2,878,891; 3,074,878; 3,835,029; 4,288,235; 4,348,364; 4,756,886; 4,961,863; 5,259,855; 5,837,129; 5,837,129; 6,113,777 and 6,692,552.
With improvement of bulk desulfurizing efficiency within the FCCU process, the FCCU could fill a role as a pseudo hydrocracker operation. The process would generate high olefinicity liquefied petroleum gas (LPG), a low carbon number high hydrogen content stream for fuel cells, a low hydrogen content alkylbenzene stream for chemicals, and a tailored narrow boiling cycle oil that is significantly easier to integrate into existing refinery hardware. Optionally, the cycle oil could be eliminated completely negating the need for additional hydrogen and associated energy and CO2 generation. The FCCU would retain its carbon rejection flexibility.
Tailoring the FCCU product distribution to eliminate the 330° F. to 430° F. boiling range improves the quality of the gasoline, eliminates or reduces subsequent processing costs, and drops the driveability index of FCCU gasoline from about 1300 to 1000. Lower values of the driveability index mean improved cold-start and warm-up performance.
Further tailoring of the FCCU product distribution to remove the 600° F. to 700° F. cut eliminates the sterically hindered LCO components that are very difficult to hydrotreat. Ideally, these low hydrogen content components could be utilized as coke and eliminate the hydrogen, energy, and capital required to upgrade this stream into the high hydrogen content fuels.
The 700° F.+FCCU slurry has a niche in heavy oil upgrading and coke related products. The high boiling nature of the FCCU slurry allows it to act as a liquid catalyst in some heavy oil upgrading processes.
In recent times, hydrocarbon catalytic cracking processes increasingly employ a system whereby the hydrocarbon feedstock is cracked in the presence of a high activity cracking catalyst in a riser-type reactor. In general the FCC process proceeds by contacting hot regenerated catalyst with a hydrocarbon feed in a reaction zone under conditions suitable for cracking; separating the cracked hydrocarbon gases from the spent catalyst using a gross cut separator followed by conventional cyclones; steam stripping the spent catalyst to remove hydrocarbons and subsequently feeding the stripped, spent catalyst to a regeneration chamber where a controlled volume of air is introduced to burn the carbonaceous deposits from the catalyst, and returning the regenerated catalyst to the reaction zone.
In order to prevent overcracking, after transit of the reactor, it is desirable to quickly make a gross cut separation of the catalyst from the cracked products. In this regard, the industry has produced many different types of separation devices for effecting the gross cut separation. See, e.g., U.S. Pat. Nos. 2,737,479; 2,878,891; 3,074,878; 4,288,235; 4,348,364; 3,835,029; 4,756,886; 5,259,855; 4,961,863; 5,837,129; 6,113,777; among others. An especially useful device, for use in the prior art and in the present invention is the Riser Termination Device (RTD), which is described and claimed in Benham, U.S. Pat. No. 6,692,552.
The use of the more efficient of these known separators, such as those described in U.S. Pat. Nos. 4,288,235; 5,837,129 and 6,113,777, and especially the RTD (U.S. Pat. No. 6,692,552), results in efficient disengaging of spent catalyst and product vapors, thereby reducing non-selective post-riser reactions and resulting in low gas make and delta coke. The RTD separator system has an integrated degassing system to reduce further the amount of hydrocarbon that reaches the stripper. The unit coke balances in these systems have been maintained by blending the base feedstocks with coker slurry, heavy fuel oil (HFO) or vacuum tower bottoms (VTB) (the undistilled fraction in a vacuum distillation) to adjust coke and slurry precursor levels of between 10 and 16 weight percent. The units typically operate with delta cokes of about 0.6 weight percent resulting in catalyst to oil ratios in the 8 to 10 range.
Additionally, it has been known that certain feedstocks to FCC units can be pretreated to remove sulfur, such as by hydrotreating, as is known to those skilled in the art. With the improved separator systems, especially those providing improved stripping prior to entry of the catalyst into the dense catalyst bed in the disengaging vessel, such as with the RTD bathtub system (described in the aforementioned U.S. Pat. No. 6,692,552), certain heat balance problems have arisen. In solving the problems of the prior art, the present inventor first has established differentiation criteria for the sulfur in gasoline behavior of feedstocks. The criteria are based on the bulk aromatic sulfur content of the FCC feedstock. Using these criteria, the present inventor has found:                (1) interaction from feedstocks generally accepted as being non-reactive results in shifts in heteroatom concentrations and carbon distribution. Blending of these feedstocks with the bulk FCC feed results in reduced heteroatom content of the FCC product as well as a redistribution of the carbon number and the hydrogen of the net FCC product that is very advantageous.        (2) a very direct impact on catalyst (including most significant results from gasoline sulfur reduction additive published to date) influence on the gasoline sulfur concentrations in the process.        (3) the ability to relate the aromatic sulfur content of feedstocks in such a system so that they can be segregated and processed appropriately.        (4) H2S and olefin recombination are hypothesized to be the primary reaction system to control thiophenes as further focused on in the severe hydrotreated feedstock lab work-up and the C5-C6 co-processing work. In particular, the characteristics of the RTD significantly reduce the amount of these materials passing from the reactor into the stripper system as well as reduce the length of time these materials are in contact with each other in the riser. Sulfur reduction additives for use in FCC units are well known to those skilled in the art. Particularly beneficial additives for use in the practice of the present invention are those sold by Akzo Nobel under the trademark RESOLVE®. It is believed by the present inventors that the use of sulfur reduction additives in the practice of the present invention are more particularly beneficial in FCC units employing the RTD separator system due to its more efficient degassing. Use of the RTD system provides less control on the sulfur contributed from the aromatic sulfur species in the feedstock, but significantly more influence on the thiophenes and mercaptans generated in the FCC unit from the olefin and H2S recombination.        
Processing severely hydrotreated feedstocks or very low aromatic sulfur feedstocks in modern FCC units, especially those employing the RTD system, has proved difficult because coke and slurry precursor levels may be insufficient to generate a comfortable heat balance. Table I below shows general feedstock properties in this regard.
TABLE ISweetTar SandsSyncrudeGas OilHT#1HT#2HT#3HTBottoms% HT090.792.997.399.199.5+Density0.8960.8910.8910.8910.9090.895ACE Conversion (wt %)78.386.686.387.982.486.1Precursors (wt %)Gasoline79.585.985.787.085.290.4LCO9.77.127.126.617.275.02Coke and slurry10.86.967.136.417.524.59Wt % boiling <650° F.24.600000Aromatic sulfur (wt %)2.780.690.650.731.801.01Benzothiophenes1.080.090.030.060.540.18Dibenzothiophenes1.380.510.620.621.180.80Tribenzothiophenes0.320.090.000.060.080.02Sulfur (wppm)718274356121520065CFHTU LHSVNA1.50.80.80.501.0Gasoline sulfur (wppm)698262619816Light cut (183 F.−)44.76.03.53.01.51.5Mid cut (183-350 F.)369.113.716.913.35.611.4Thiophene546.56.56.02.56.0Thiophene (% mid cut)154839454453Heavy cut (350-430)284.66631.51.5Benzothiophene208.66631.51.5Benzothiophene (%73.3100100100100100heavy cut)Gasoline sulfur (% feed sulfur)9.73.54.88.94.024.0LCO S (430-650) wppm21977260723861008425232LCO S (% feed sulfur)306351425469213357HCO S (650+ F.) wppm13997233825001041100100HCO S (% feed sulfur)19531544648450154The base feedstock is a representative virgin crude gas oil mix containing about 24.6 volume percent material boiling below 650F. Hydrotreated gas oils #1-3 represent three levels of hydrotreating of the base gas oil using variations in LHSV and operating temperature. All hydrotreated gasoils are cut at 650F. The desulfurization of the 650F plus conventional gas oil ranged from 90.7 to 97.3 percent and the hydrotreated feed sulfur ranged from 743-215 wppm.
Full range gasoline sulfur ranged from 26 to 19 wppm with most of the sulfur in the 183 to 350 F mid cut. The percentage of the feed sulfur routed to the gasoline increased with increased feedstock desulfurization in the CFHTU pilot plant.
The net desulfurization efficiency for the two tar sands sourced gasoils is over 99%. The gasoline sulfur for the 2700 psi hydrocracker bottoms is 24% of feed sulfur. The cycle oil sulfur concentration is higher relative to the base sweet gasoil feedstock in all the cases except the low LHSV 1900 psi tar sands operation. The elevated thiophenes and the reduced benzothiophenes are mercaptans in all the hydrotreated cases suggest the sulfur formed is undergoing recombination reactions with the olefins and generating the majority of the thiophenes and alkylthiophenes. The cracking studies for all the feedstocks indicate that the thiophene concentration in the gasoline increases with conversion.
The data suggest the minimum sulfur level that can be achieved by increasing the feed desulfurization level will be limited until the cycle oil sulfur levels are reduced sufficiently. Alternatively, to achieve very low gasoline sulfur levels, the FCCU would have to be set up to inhibit the olefin and H2S recombination reaction.
The novel approach taken by the present inventor unexpectedly was built on the advantages of the more efficient riser disengager systems to rapidly separate riser products, especially the RTD system. The condensed aromatics produced by the FCC unit cracking process are recovered from the fractionation system and injected into the stripper to generate coke to adjust the unit heat balance. This second stage cracking system is added below the first separator, e.g., RTD in the top of the conventional stripper. The introduction of light cycle oil (LCO), a fraction of FCC product liquid distilling between about 400° F. and about 700° F., (or an alternate fuel) into the long contact, high catalyst to oil, dense bed cracking system is targeted to convert the majority of the low hydrogen LCO stream into coke. The high cat/oil ratio (in the range of about 100), combined with very low levels of coke on the catalyst entering the dense bed contacting zone also enhances the reduction of sulfur by use of the sulfur reduction additive (such as RESOLVE®) for the non-coked vapors generated from the LCO and routed to product recovery.
For example, the Petro-Canada FCCUs employ a proprietary Riser Termination Device (RTD) developed by Petro-Canada and licensed by Shaw Stone and Webster, which results in efficient disengaging of catalyst and product vapors. Non-selective post-riser reactions are minimized resulting in low gas make and delta coke. The RTD system has an integrated degassing system to minimize the amount of hydrocarbon reaching the stripper. The unit coke balances typically have been maintained by blending the base feedstocks with coker slurry, HFO or VTB to adjust coke and slurry precursor levels of between 10 and 16 wt %. The units typically operate with delta cokes of about 0.6 wt % resulting in cat/oils in the 8 to 10 range.
In order to process severely hydrotreated feedstocks or very low aromatic sulfur feedstocks, adjustments have to be made to the FCCU processing scheme. Coke and slurry precursor levels are insufficient to generate a comfortable heat balance with some of these very low aromatic sulfur feedstocks.
The approach taken by Petro-Canada was to build on the advantages of the efficient riser disengager system to rapidly separate riser products. The condensed aromatics produced by the FCCU cracking process are recovered from the fractionation system and injected into the stripper to generate coke to adjust the unit heat balance. This second stage cracking system is added below the RTD in the top of the conventional stripper. The introduction of the LCO into the long contact, high cat to oil, dense bed cracking system is targeted to convert the majority of the low hydrogen LCO stream into coke. The high cat/oil ratio (in the range of 100) combined with very low levels of coke on the catalyst entering the dense bed contacting zone should enhance the reduction of sulfur by the RESOLVE® additive for the non-coked vapors generated from the LCO and routed to product recovery. By removing the dependency of the FCCU on coke generated from feedstock contact in the riser, the application of FCCU process is broadened to encompass a wide range of feedstocks.
This novel integrated process configuration provides many processing advantages, such as:                (1) Independent heat balance control for a fuel deficient system. As an example, this allows for decoupling the catalytic feed hydrotreating unit (CFHTU) severity effect on the fluid catalytic cracking unit (FCCU) heat balance from the CFHTU product desulfurization target. The gasoil sulfur is tied directly to the desulfurization level achieved on the other products and the conversion achieved in the CFHTU or hydrocracker. This allows for decoupling the requirements to achieve a higher coke and slurry containing feedstock from the FCCU from the hydroprocessor design criteria. This will allow for simplification of the hydroprocessor.        (2) Lower delta coke in the riser providing more selective catalytic processing at higher catalyst activity.        (3) Rapid separation of the olefin and H2S at the end of the riser that reduces sulfur recombination reactions.        (4) Utilization of the low hydrogen content product for fuel and providing sufficient time for the polyaromatic coke to be formed from the light cycle oils.        (5) Partitioning of the olefin exiting the riser from the sulfur contained in the fuel charged to the stripper to minimize sulfur recombination reactions.        (6) Ability to process higher sulfur content feedstocks and process higher aromatic sulfur feedstocks.        (7) Co-processing of low carbon number feedstocks for improved net carbon distribution, heteroatom removal and hydrogen management.        (8) Bulk processing of a wider range of feedstocks in the FCCU and the associated elimination of the complexity and efficiency of additional processing steps.        (9) Segregation of feedstock based on aromatic sulfur content.        (10) Direct disposal of low quality, high aromatic sulfur feedstocks, such as coker slurry in the second stage system.        
Moreover, the integration of recycle streams from the main fractionator provides further process advantages, including, but not limited to:                (1) Tailored carbon distribution product and flexibility in hydrogen production within the refinery.        (2) Isolation of low hydrogen content aromatics produced in first pass cracking so that they can be exposed to severe cracking at long residence time and very high cat/oil ratios.        (3) Sulfur and nitrogen removal as polar compounds preferentially are converted to coke.        (4) Enhancement of the sulfur reduction efficiency of the sulfur reduction additive technologies, such as, but not limited to, the RESOLVE® technology.        (5) Energy efficiency.        